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been observed and can be used to infer what might be the size of the largest induced
seismic events, if the volume of injected or extracted fluid is known. However, the
correlation cannot be used to directly infer hazard or risk associated with various
energy technologies.
4.
These data and the limitations described point toward the great value in collecting
information about well projects and characteristics, including the size of earth-
quakes produced (if any). Data are critical to making progress in estimating hazard
and risk (see Chapter 5).
Another important factor to consider in evaluating the potential for an energy project
to induce felt seismic events is the variation in volume from technology to technology, and
the variation in net volume over time (Figure 3.17). For example, although CCS does not
have the highest daily injection volumes among the technologies investigated, it does have
the highest annual injected volumes because the projects are designed to run continu-
ously with relatively large injection volumes. Also, CCS, similar to waste and wastewater
disposal, involves only net addition of fluid to a reservoir rather than both injection and
extraction that occur with oil and gas production and geothermal energy development.
This characteristic is represented in the bottom graph in Figure 3.17 by the high net vol-
umes of fluid injected for both technologies. Comparatively, the two geothermal cases (The
Geysers and the EGS project at Basel) and hydraulic fracturing for shale gas production
have negative or low net injection volumes on an annual basis. In the case of The Geysers,
the negative net fluid volume is due to the high volumes of fluid extracted; annually, the
fluid volume in The Geysers reservoir has actually been declining yearly, despite the high
injection volumes.
The tens of thousands of Class II water disposal wells located across the United States
have proven to be mostly benign with respect to induced seismicity. However, there are
clearly troublesome areas that have induced events as large as
M
4.7 (Arkansas, 2011; see
Horton, 2012) that warrant a closer examination. The dramatic increase in hydraulic fractur-
ing over the past 5 years means an increased volume of wastewater from hydraulic fracturing
requiring disposal. If the number of available Class II wastewater disposal wells remains the
same, the volume of injected fluid in each well must increase to accommodate the increased
wastewater. The long-term effect of this increased volume on the potential to induce felt
seismic events is unknown but could be of concern.
The implication for subsurface storage demonstration sites, for instance for CO
2,
is
that pilot plants that inject small volumes of fluid cannot be expected to represent or bound
the induced seismicity that might occur for production plants that will inject much larger
volumes. Evaluation of production facilities for large-scale CCS thus requires a complete
presentation of the risk of induced seismicity and a comprehensive monitoring plan includ-
ing bottom-hole pressures and time response to different injection regimes.
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